Integrating Multiple Data Sources for Drilling Applications

ABSTRACT

A drilling system makes measurements of at least one drilling parameter such as downhole weight on bit, bit torque, bit revolutions, rate of penetration and bit axial acceleration, and at least one measurement responsive to formation properties. One or more processors use the measurements of drilling parameters and formation properties to adjust drilling parameters.

CROSS-REFERENCES TO RELATED APPLICATIONS

This application claims priority from U.S. Provisional PatentApplication Ser. No. 61/260,069 filed on Nov. 11, 2009 and from U.S.Provisional Patent Application Ser. No. 61/371,998 filed on Aug. 9,2010.

BACKGROUND OF THE DISCLOSURE

1. Field of the Disclosure

This disclosure relates to systems, devices and methods that utilizedynamic measurements of selected drilling parameters and measurementsindicative of the lithology of a formation being drilled for controllingdrilling operations.

2. The Related Art

To obtain hydrocarbons such as oil and gas, boreholes are drilled byrotating a drill bit attached at a drill string end. A large proportionof the current drilling activity involves directional drilling, i.e.,drilling deviated and horizontal boreholes, to increase the hydrocarbonproduction and/or to withdraw additional hydrocarbons from the earth'sformations. Modern directional drilling systems generally employ a drillstring having a bottomhole assembly (BHA) and a drill bit at end thereofthat is rotated by a drill motor (mud motor) and/or the drill string. Anumber of downhole devices placed in close proximity to the drill bitmeasure certain downhole operating parameters associated with the drillstring. Such devices typically include sensors for measuring downholetemperature and pressure, azimuth and inclination measuring devices andsensors that measure the acceleration of the BHA in different directionsand the bending moment. The latter data are used to characterize thedrilling dynamics of the BHA, which depends on formation properties, thedrill bit and the BHA configuration.

Additional downhole instruments, known as logging-while-drilling (“LWD”)tools, are frequently attached to the drill string to determine theformation geology and formation fluid conditions during the drillingoperations. Logging-while-drilling (LWD) systems, orMeasurement-While-Drilling (MWD) systems, are known for identifying andevaluating rock formations and monitoring the trajectory of the boreholein real time. For example, a resistivity measuring device is attached todetermine the presence of hydrocarbons and water. An MWD set of tools isgenerally located in the lower portion of the drill string near the bit.The tools are either housed in a section of drill collar or formed so asto be compatible with the drill collar. It is desirable to provideinformation of the formation as close to the drill bit as is feasible.Several methods for evaluating the formation using sensors near thedrill bit have been employed. These methods reduce the time lag betweenthe time the bit penetrates the formation and the time the MWD toolsenses that area of the formation. Another approach to determineformation or lithology changes has been to use the mechanic measurementsavailable downhole and at the surface, such as measured rate ofpenetration (ROP) and bit revolutions per minute (RPM) and average ormean downhole weight on bit (WOB) and average or mean downhole torque onthe bit (TOR) that are derived from real time in situ measurements madeby an MWD tool.

The present disclosure is directed towards the use of measurements ofdrilling dynamics and measurements indicative of formation lithology forcontrol of drilling operation.

SUMMARY OF THE DISCLOSURE

One embodiment of the disclosure is a method of conducting drillingoperations. The method includes conveying a bottomhole assembly into aborehole in the earth formation, making dynamic measurements of at leastone drilling parameter, using a formation evaluation (FE) sensor to makeat least one FE measurement indicative of a property of the formation,and controlling a drilling operation using the at least one drillingparameter and the at least one FE measurement.

Another embodiment of the disclosure is an apparatus for conductingdrilling operations. The apparatus includes a bottomhole assemblyconfigured to be conveyed into a borehole in the earth formation, atleast one first sensor configured to dynamically measure at least onedrilling parameter at a downhole location, at least one formationevaluation (FE) sensor configured to make at least one FE measurementindicative of a property of the formation, and at least one processorconfigured to control a drilling operation using the measurement of theat least one drilling parameter and the at least one FE measurement.

BRIEF DESCRIPTION OF THE DRAWINGS

For a detailed understanding of the present disclosure, reference shouldbe made to the following detailed description of the preferredembodiment, taken in conjunction with the accompanying drawings:

FIG. 1 is an elevation view of an exemplary drilling system suitable foruse with the present disclosure

FIG. 2 is a block diagram of one exemplary system in accordance with thepresent disclosure for determining the lithology of a formation whiledrilling;

FIGS. 3 a and 3 b show exemplary resistivity measurements that may beused for geostopping;

FIG. 4 shows an exemplary cross-plot of downhole torque againstresistivity;

FIG. 5 shows an example of a hierarchical clustering tree;

FIG. 6 illustrates the identification of thief zones from resistivitylogs along with recorded annular pressures, the cumulative pit and tankvolumes and the gamma ray log;

FIG. 7 a shows an exemplary data set recorded using a quadrupole loggingtool in a transversely isotropic medium;

FIG. 7 b shows a result of the semblance analysis of the data of FIG. 7a identifying the slow and fast modes;

FIG. 8 shows an embodiment of the present disclosure using a near-bitgamma ray sensor; and

FIG. 9 shows another embodiment of the present disclosure using anear-bit gamma ray sensor and a resistivity sensor.

DETAILED DESCRIPTION OF THE DISCLOSURE

The teachings of the present disclosure can be applied in a number ofarrangements to generally improve the drilling process by usingindications of the lithology of the formation being drilled. As isknown, formation lithology generally refers to an earth or rockcharacteristic such as the nature of the mineral content, grain size,texture and color. Such improvements may include reduced drilling timeand associated costs, safer drilling operations, more accurate drilling,improvement in ROP, extended drill string life, improved bit and cutterlife, reduction in wear and tear on BHA, and an improvement in boreholequality. The present disclosure is susceptible to embodiments ofdifferent forms. These are shown in the drawings, and herein will bedescribed in detail, specific embodiments of the present disclosure withthe understanding that the present disclosure is to be considered anexemplification of the principles of the disclosure, and is not intendedto limit the disclosure to that illustrated and described herein.

Referring now to FIG. 1, there is shown an exemplary drilling system 20suitable for use with the present disclosure. As is shown, aconventional rig 22 includes a derrick 24, derrick floor 26, draw works28, hook 30, and swivel 32 A drillstring 38 which includes drill pipesection 40 and drill collar section 42 extends downward from rig 22 intoa wellbore 44. Drill collar section 42 preferably includes a number oftubular drill collar members which connect together, including ameasurement-while-drilling (MWD) subassembly including a number ofsensors and cooperating telemetry data transmission subassembly, whichare collectively referred to hereinafter as “MWD system 46”. The drillstring 38 further includes a drill bit 56 adapted to disintegrate ageological formation and known components such as thrusters, mud motors,steering units, stabilizers and other such components for forming awellbore through the subterranean formation 14. Other related componentsand equipment of the system 20 are well known in the art and are notdescribed in detail herein.

Also, it should be understood that applications other than rotary drives(e.g., coiled tubing applications) may utilize other equipment such asinjectors, coiled tubing, a drilling motor, thrusters, etc. Drillingsystems utilizing coiled tubing as the drill string are within the scopeof the present disclosure.

The MWD system 46 includes sensors, circuitry and processing firmwareand software and algorithms for providing information about desireddynamic drilling parameters relating to the BHA, drill string, the drillbit and downhole equipment such as a drilling motor, steering unit,thrusters, etc. (collectively, a bottomhole assembly or BHA). Exemplarysensors include, but are not limited to, drill bit sensors, an RPMsensor, a weight on bit sensor, sensors for measuring mud motorparameters (e.g., mud motor stator temperature, differential pressureacross a mud motor, and fluid flow rate through a mud motor), andsensors for measuring acceleration, vibration, whirl, radialdisplacement, stick-slip, torque, shock, vibration, strain, stress,bending moment, bit bounce, axial thrust, friction, backward rotation,BHA buckling and radial thrust. Sensors distributed along the drillstring can measure physical quantities such as drill string accelerationand strain, internal pressures in the drill string bore, externalpressure in the annulus, vibration, temperature, electrical and magneticfield intensities inside the drill string, bore of the drill string,etc. Suitable systems for making dynamic downhole measurements includeCOPILOT™, a downhole measurement system, manufactured by Baker HughesIncorporated. Suitable systems are also discussed in “Downhole Diagnosisof Drilling Dynamics Data Provides New Level Drilling Process Control toDriller”, SPE 49206, by G. Heisig and J. D. Macpherson, 1998.

The MWD system 46 can include one or more downhole processors 70. Theprocessor(s) 70 can include a microprocessor that uses a computerprogram implemented on a suitable machine readable medium that enablesthe processor to perform the control and processing. The machinereadable medium may include ROMs, EPROMs, EAROMs, Flash Memories andOptical disks. Other equipment such as power and data buses, powersupplies, and the like will be apparent to one skilled in the art. Inone embodiment, the MWD system 46 utilizes mud pulse telemetry tocommunicate data from a downhole location to the surface while drillingoperations take place. To receive data at the surface, a transducer 60is provided in communication with mud supply line 54. This transducergenerates electrical signals in response to drilling mud pressurevariations. These electrical signals are transmitted by a surfaceconductor 62 to a surface electronic processor 64, which is preferably adata processing system with a central processing unit for executingprogram instructions, and for responding to user commands. For systemsutilizing mud pulse telemetry or other systems having limited datatransfer capability (e.g., bandwidth), the system can utilize thedownhole processor 70 in conjunction with the surface processor 64. Forexample, the downhole processor 70 can process the downhole measureddata and transmit reduced data and/or signals indicative of thelithology being drilled to the surface. The surface processor 64 canprocess the surface measured data, along with the data transmitted fromthe downhole processor 70, to evaluate formation lithology.

In another embodiment, the MWD system 46 utilizes a telemetry systemproviding relatively high bandwidth; e.g., conductive wires or cablesprovide in or along the drill string, radiofrequency (RF) orelectromagnetic (EM)-based systems, or other systems. In such systems,“raw” or unprocessed data, in addition to or instead of processed data,can be transmitted to the surface processor 64 for processing. In suchan arrangement, a downhole processor 70 may not be needed. In anotherarrangement, the surface measurements are transmitted downhole and thedownhole processor 70 processes the surface and downhole data. In thisarrangement, only the downhole processor 70 is used to obtainlithological indications. It should therefore be appreciated that anumber of arrangements can be used for the processor 205 of FIG. 2;e.g., a surface processor that processes downhole and surfacemeasurements, a downhole processor that processes downhole and surfacemeasurements, and a surface and downhole processor that cooperativelyprocess downhole and surface measurements.

Referring now to FIG. 2, there is shown in block diagram form oneexemplary system made in accordance with the present disclosure forcontrolling drilling operations using measurements indicative of alithology of a formation being drilled. The system includes a processoror processors 205 that communicate with downhole and surface sensors.The downhole sensors include two types of sensors. The surface sensorsinclude one or more sensors that can dynamically measure drillingparameters such as instantaneous torque, weight on bit, and RPM of thedrill bit. For the purposes of the present disclosure, the steeringforce, equivalent circulation density (ECD), and near bit inclinationare also considered drilling parameters. Thus, dynamic measurements canprovide greater details as to the behavior of a drill bit, drill string,or BHA during drilling.

The processor 205 uses measurements of drilling dynamics 201. Inaddition, the processor also uses measurements of formation properties203. These may include gamma-ray measurements, resistivity measurements,acoustic (sonic)measurements, neutron porosity measurements and/or bulkdensity measurements. For gamma-ray measurements, the sensor arrangementdisclosed in US Patent publication 20100089645 of Trinh et al., havingthe same assignee as the present disclosure and the contents of whichare incorporated herein by reference, may be used. Disclosed therein isa drill bit that includes a bit body and a gamma ray sensor in the bitbody. An advantage of this sensor arrangement is that gamma raymeasurements indicative of formation lithology are made substantiallysimultaneously at the bit location. The use of the device of Trinh isnot to be construed as a limitation and other arrangements may be usedto provide gamma ray measurements.

For resistivity measurements, the sensor arrangement disclosed in U.S.Pat. No. 7,554,329 to Gorek et al., having the same assignee as thepresent disclosure and the contents of which are incorporated herein byreference, may be used. As disclosed therein, the drillbit and theadjacent portion of the drill collar are used as a focusing electrodefor focusing the measure current from a measure electrode on the face orside of the drillbit. This provides the ability to see ahead of andazimuthally around the drillbit. The use of the device of Gorek is notto be construed as a limitation and other arrangements may be used toprovide gamma ray measurements. For example, the device disclosed inU.S. Pat. No. 6,850,068 to Chemali et al., having the same assignee asthe present application and the contents of which are incorporatedherein by reference, may be used.

One embodiment of the disclosure uses, as an acoustic sensor, thequadrupole acoustic tool disclosed in U.S. Pat. No. 6,859,168 of Tang etal., having the same assignee as the present disclosure and the contentsof which are incorporated herein by reference, may be used. The loggingtool of this invention includes a transmitter conveyed on a drillingcollar for exciting a quadrupole signal in a borehole being drilled by adrill bit and a receiver for receiving the signal. The transmitter isoperated at a frequency below the cut-off frequency of the quadrupolecollar mode. The received signal consists primarily of the formationquadrupole mode which, at low frequencies, has a velocity thatapproaches the formation shear velocity. The transmitter, in oneembodiment, consists of eight equal sectors of a piezoelectric cylindermounted on the rim of the drilling collar. The value of the cut-offfrequency is primarily dependent on the thickness of the drillingcollar. Alternatively, the transmitter may be operated to produce boththe collar mode and the formation mode and a processor may be used tofilter out the collar mode. U.S. patent application Ser. No. 11/502,792(Patent Publication US 2007/0127314, now abandoned) of Georgi disclosesa method of using resistivity measurements to predict overpressuredformations ahead of the drillbit.

U.S. Pat. No. 7,650,241 to Jogi et al. having the same assignee as thepresent disclosure and the contents of which are incorporated herein byreference, teaches the determination of formation lithology usingdrilling dynamics measurements. Using a database, the processor(s) 205outputs an indication of the lithology, which can serve a number ofpurposes, such as optimizing or adjusting drilling parameters, issuingdrilling alerts relating to faults, high-pressure zones, geosteering theBHA, etc. In the present disclosure, using lithology measurements anddrilling parameter measurements, the lithology is identified 207. Inparticular, if the lithology sensors are able to see ahead of the sensoror even ahead of the drillbit, changes in lithology may be anticipatedand drilling parameters may be adjusted 209.

Turning to FIG. 3 b, an exemplary near bit resistivity measurement isshown. At the depth indicated by 305, there is a change in lithology asindicated by the resistivity curve 301. In this particular instance, itwas desired to stop the drilling (“geostopping”) prior to penetration ofthe formation below depth 305. This basically means doing thegeostopping based on the curve 303. As can be seen, identification ofthe deflection of the resistivity curve from a baseline defined bymeasurements above the depth 305 is not an easy task. The device ofGorek would have greater sensitivity to an approaching bed boundary,particularly if the boundary is approached at an inclination andazimuthal measurements made during rotation are used.

Formation evaluation measurements may or may not have a “look ahead”capability. The amount of look ahead determines the reference point ofthe sensor. For an at-bit measurement such as drilling dynamicsmeasurements this should be the bit face. FE measurements are sensitiveto the rock volume close to their sensor. Drilling dynamics measurementsrelate to the dynamic state of the BHA. One important factor determiningthis state is the bit-rock interaction. Thus it can be said thatdrilling parameters are sensitive to the rock formation at the bit. Whenusing measurements with a “look ahead” capability, i.e. sensitive closeto the bit or ahead of the bit, they may be combined with drillingdynamics measurements. This may be done by combining multiplemeasurements to derive a single (or multiple) indicators. For instanceformation evaluation measurements and drilling dynamics data combinedmay be used to determine a lithology indicator. Algorithms that may beused include deterministic inversion, neural networks, any statisticalclassification, multiple regression, etc. For example, U.S. Pat. No.7,193,414 to Kruspe, having the same assignee as the present disclosureand the contents of which are incorporated herein by reference,discloses the use of an expert system for using formation evaluationmeasurements for determination of formation lithology. In one embodimentof the present disclosure, the input to the expert system includesdrilling dynamics measurements. The expert system described in Kruspemay be implemented as a neural net that has been trained and validated.The same methods may be used if FE sensors are used that are notsensitive at the bit. In this case the different data sources need to bedepth-matched based on the time-depth assignment.

An exemplary method for combining a formation evaluation measurement anda drilling dynamic measurement is by using crossplots. Shown in FIG. 4are crossplots of near-date resistivity (abscissa 401) against downholetorque (ordinate 403). The measurements in an earlier period are shownwithin the group 405 and are relatively stable. The more recentmeasurements 407 show a noticeable difference from the earliermeasurements and are diagnostic of a lithology change. Identification ofsuch a change in character can be made with more confidence usingmultiple measurements than with a single measurement as in FIG. 3.

Such a change in behavior can be identified using standard statisticaltests. For a single measurement, such as resistivity at bit, a simpleimplementation is as follows:

-   -   Take a base sample, for instance data from the last 10 min    -   Take the current sample, for instance data from the last 2 min    -   Compute mean and standard deviation for both samples    -   Test hypotheses whether both samples belong to the same        population, for instance use student t-test        -   Compute test measure T from mean and standard deviation        -   Compute significance level t_(t,k) for defined significance            level a (usually 0.05) and number of data points        -   If T>t_(a,k), with (1−α) confidence (i.e. 95% for α=0.05)            the samples are not from the same population i.e. the            formation is changing        -   set formation change flag    -   If the flag is set, display a warning.

When multiple data measurements are used, the problem is somewhat morecomplicated. In principle, with a total of n₁ drilling dynamicsmeasurements and n₂ formation evaluation measurements, it is possible todefine a multivariate distribution of n₁+n₂ dimensions characterizingthe measurements and doing a statistical test to see if the distributionover a first time interval is different from the distribution over asecond time interval, a problem arises in having a sufficient number ofsamples to get a meaningful estimate of the multivariate distributions.Accordingly, in one embodiment of the disclosure, a clustering of thedata is done. This may be a hierarchical clustering, such as thatillustrated in FIG. 5. Each data sample represents drilling dynamics andformation evaluation measurements. On the left of the plot, we startwith each data sample as being in a class by itself. Samples are thenlinked into larger and larger clusters by using a measure of distancesuch as a Euclidean distance. In one embodiment of the disclosure,distances between clusters are determined by the greatest distancebetween any two samples in two clusters. This method is appropriatewhen, as in this case, the samples naturally form distinct groups (e.g.,Lithology A and Lithology B, or Continue drilling and Stop drilling).The choice of the particular method of clustering is not be construed asa limitation and other methods known in the art could be used.

Another embodiment of the disclosure is directed towards using downholedrilling dynamics and formation evaluation data to test a strategy forusing losses for fracture gradient calibration. The strategy includesthe detection of losses, the identification of the zones where lossestook place (thief zones), and the characterization of thief zones.Losses can result from initiating fractures in the borehole wallwhenever the annular pressure exceeds the load the borehole wall canbear. For undamaged borehole walls, the maximum load before fracturesare initiated is the least principle near-field stress (which isre-distributed) around the borehole plus the tensile rock strength(which needs to be neglected when the borehole wall is damaged or iffractures already exist). Although fracture initiation may notnecessarily result in significant losses, the propagation of thefracture into the far-field formations can be important. Losses causedby propagating fractures are thus encountered whenever the annularpressure exceeds the far-field minimum principle stress (existence offractures presumed). The observation of mud losses can therefore be usedto calibrate the fracture gradient. The losses indicate that the annularpressure exceeded the far-field minimum principle stress, provided thatother causes such as faults or naturally fractured formations can beexcluded.

FIG. 6 shows a plot 601 of the drilling depth (ordinate in the top plot)against time. Also shown are several resistivity logs, collectivelydenoted by 603, and the gamma ray log 605. The second plot shows thecumulative mud losses in the borehole 607 as a function of time and thethird plot shows the ECD 609. The ECD is defined in the SchlumbergerOilfield Glossary as:

-   -   The effective density exerted by a circulating fluid against the        formation that takes into account the pressure drop in the        annulus above the point being considered.        Attention is drawn to the time intervals 611, 613 and the        corresponding depth intervals 611′, 613′. In this interval,        particularly in the deeper interval, there is considerable        leakage of mud into the formation as indicated by the curve 607.        The ECD also drops in these intervals as indicated by 609. In        these intervals, there is a separation of the resistivity logs        603. Specifically, the high frequency resistivity measurements        are greater than the low frequency resistivity measurements.        This is consistent with invasion of the formation by the        nonconductive borehole mud that would have a greater effect on        the shallow (high frequency) measurements than on the deep (low        frequency) measurements.

One objective in conducting drilling operations is to maintain the ECDbelow the load capacity of the borehole wall. This is done by adjustingthe flow rate and/or the mud weight at the surface while, at the sametime, avoiding a blowout of the well due to insufficient boreholepressure. Identification of zones of weakness plays an important role inthis. Rapid identification of these zones will be facilitated by havingthe resistivity measurement at bit, at the same time as the ECDinformation. In another setup, a change in the dynamic forces on the BHAis observed when drilling into the weak zone. This gives an additionalindicator of the approaching zone.

For this particular well, the shear velocity logs were not processed tospecifically identify fractures. For MWD measurements, the quadrupolelogging tool of Tang discussed above is used. It is well known in theart that the effect of aligned fractures in the subsurface is to producea transverse isotropy in the velocity of propagation of shear waves.This can manifest itself in two ways. One is a variation in the velocityof propagation with the direction of propagation. The other is asplitting of shear waves into a “fast mode” and a “slow mode” dependingupon the direction of polarization. Specifically, shear wavespropagating with a polarization parallel to the fracture planes have ahigher velocity than shear waves propagating with a polarization atright angles to the fracture planes.

FIG. 7 a shows a shot panel recorded with a quadrupole logging tool in atransversely isotropic medium. In this particular example, thetransverse isotropy was due to layering and not due to fracturing, butthe mathematics of the wave propagation is the same. FIG. 7 b shows aresult of a semblance analysis of the data of FIG. 7 a in which a fastmode and a slow mode can clearly be seen.

In one embodiment of the disclosure, seismic sensors may be used toconduct a vertical seismic profile (VSP). The VSP has a capability oflooking ahead of the drillbit, and the VSP data may be processed usingknown methods to estimate shear velocities ahead of the drillbit. Theseshear velocities are diagnostic of fracturing in the formation. Shearvelocities ahead of the drillbit may also be estimated using a methoddisclosed in U.S. patent application Ser. No. 12/139,179 of Mathiszik etal., (US Patent Publication 2008/312839) having the same assignee as thepresent disclosure and the contents of which are incorporated herein byreference. In the method described by Mathiszik: a downhole acousticlogging tool is used for generating a guided borehole wave thatpropagates into the formation as a body wave, reflects from an interfaceand is converted back into a guided borehole wave. Guided borehole wavesresulting from reflection of the body wave are used to image areflector.

Fracturing of the formation may also be detected using commonly usedimaging instruments, such as resistivity, nuclear and acoustic images ofthe borehole using known devices and methods.

Estimates of the rock strength may be made using bulk densitymeasurements and/or porosity measurements. The porosity measurements maybe obtained using a nuclear source or by nuclear magnetic resonancemeasurements.

Turning now to FIG. 8, shown therein is lower end of a modular drillingassembly. The modular drilling motor is depicted by 801. A modularthread connection is indicated by 803. A modular gamma ray sensor isindicated by 805 and the steering unit is indicated by 807. Thisarrangement of the gamma ray sensor is only for exemplary purposes. Inone embodiment of the disclosure, the near-bit gamma ray sensor 805 maybe run without a modular drilling motor 801. In an alternate embodimentof the disclosure, the gamma ray sensor may be closer to the drillbit,e.g., in the bit box 809. A natural-gamma ray detector suitable for hightemperature using a wide band-gap photodiode has been disclosed in U.S.patent application Ser. No. 12/694,993 of Nikitin et al., having thesame assignee as the present disclosure and the contents of which areincorporated herein by reference.

FIG. 9 shows another configuration of the lower end of the drillingassembly. A resistivity at bit sensor 904 is positioned just above thenear-bit gamma ray module 805. The modular thread sub 803 is shown withthe threads exposed. The location of the resistivity at bit sensor 904relative to the near-bit gamma ray module 805 is not to be construed asa limitation. The sensor 904 could be positioned below the gamma raymodule 805.

The arrangement shown in FIG. 9 may be used for making the gamma raymeasurements and the resistivity measurements disclosed above and usedfor controlling drilling operations.

The processing of the measurements made may be done by the surfaceprocessor 64, by a downhole processor, or at a remote location. The dataacquisition may be controlled at least in part by the downholeelectronics. Implicit in the control and processing of the data is theuse of a computer program on a suitable machine readable-medium thatenables the processors to perform the control and processing. Themachine-readable medium may include ROMs, EPROMs, EEPROMs, flashmemories and optical disks. The term processor is intended to includedevices such as a field programmable gate array (FPGA).

1. A method of conducting drilling operations, the method comprising:conveying a bottomhole assembly into a borehole in the earth formation;making dynamic measurements of at least one drilling parameter at adownhole location; using a formation evaluation (FE) sensor to make atleast one FE measurement indicative of a property of the formation; andcontrolling a drilling operation using the at least one drillingparameter and the at least one FE measurement.
 2. The method of claim 1wherein the at least one drilling parameter is selected from a groupconsisting of: (i) downhole weight on bit, (ii) downhole torque on bit,(iii) drill bit revolution, (iv) drill string revolution, (v) axialacceleration, (vi) tangential acceleration, (vii) lateral acceleration,(viii) torsional acceleration, (ix) borehole pressure, (x) lateralvibration, (xi) a bending moment, and (xii) an equivalent circulatingdensity.
 3. The method of claim 1, wherein the at least one FEmeasurement is selected from: (i) a resistivity measurement, (ii) agamma ray measurement, (iii) a shear velocity measurement made by alogging tool, (iv) a shear velocity estimated using a vertical seismicprofile, (v) a borehole image. (vi) a porosity measurement, and (vii) adensity measurement.
 4. The method of claim 1 wherein the at least oneFE measurement is indicative of a property of the formation ahead of thedrillbit.
 5. The method of claim 1 wherein controlling the drillingoperation further comprises stopping further penetration of the BHA intothe formation.
 6. The method of claim 1 wherein controlling the drillingoperation further comprises at least one of: (i) selecting a mud weight,and (ii) adjusting a flow rate of mud.
 7. The method of claim 1 whereincontrolling the drilling operation further comprises at least one of:(i) controlling a direction of drilling, (ii) selecting a casing point,and (iii) selecting a coring point.
 8. The method of claim 1 whereinusing the at least one drilling parameter and the at least one FEmeasurement for controlling the drilling operation further comprisescomparing measurements made over a first time interval and measurementsmade over a second time interval of the at least one drilling parameterand the at least one FE measurement.
 9. The method of claim 8 whereincomparing the measurements made over the first time interval and themeasurements made over the second time interval further comprisesperforming a statistical analysis of the measurements.
 10. The method ofclaim 8 wherein the statistical analysis is selected from: (i) a t-test,and (ii) a cluster analysis.
 11. The method of claim 1 furthercomprising using the at least one drilling parameter and the at leastone FE measurement for characterizing a thief zone wherein a loss ofdrilling fluid is encountered.
 12. The method of claim 11 furthercomprising using an annular pressure in the borehole as an indication ofa far-field minimum principal stress in the thief zone.
 13. The methodof claim 12 further comprising using the annular pressure forcalibrating a fracture gradient in the borehole.
 14. An apparatus forconducting drilling operations, the apparatus comprising: a bottomholeassembly configured to be conveyed into a borehole in the earthformation; at least one first sensor configured to dynamically measureat least one drilling parameter at a downhole location; at least oneformation evaluation (FE) sensor configured to make at least one FEmeasurement indicative of a property of the formation; and at least oneprocessor configured to control a drilling operation using themeasurement of the at least one drilling parameter and the at least oneFE measurement.
 15. The apparatus of claim 14 wherein the at least onedrilling parameter is selected from a group consisting of: (i) downholeweight on bit, (ii) downhole torque on bit, (iii) drill bit revolution,(iv) drill string revolution, (v) axial acceleration, (vi) tangentialacceleration, (vii) lateral acceleration, (viii) torsional acceleration,(ix) borehole pressure, (x) lateral vibration, (xi) a bending moment,and (xii) an equivalent circulating density.
 16. The apparatus of claim14, wherein the at least one FE sensor is selected from: (i) aresistivity sensor, (ii) a gamma ray sensor, (iii) a shear velocitysensor, and (iv) a borehole imaging tool, (v) a porosity sensor, and(vi) a density sensor.
 17. The apparatus of claim 14 wherein thedrilling operation that the at least one processor is configured tocontrol further comprises stopping further penetration of the BHA intothe formation.
 18. The apparatus of claim 14 wherein the drillingoperation that the at least one processor is configured to controlfurther comprises at least one of: (i) selecting a mud weight, (ii)controlling a direction of drilling, (iii) selecting a casing point, and(iv) selecting a coring point.
 19. The apparatus of claim 14 wherein theat least one processor is further configured to control the drillingoperation by further comparing measurements made over a first timeinterval and measurements made over a second time interval of the atleast one drilling parameter and the at least one FE measurement. 20.The apparatus of claim 19 wherein the at least one processor is furtherconfigured to compare the measurements made over the first time intervaland the measurements made over the second time interval by furtherperforming a statistical analysis of the measurements.
 21. The apparatusof claim 20 wherein the statistical analysis performed by the at leastone processor is selected from: (i) a t-test, and (ii) a clusteranalysis.
 22. The apparatus of claim 14 wherein the at least oneformation evaluation sensor further comprises a gamma ray sensorpositioned above a steering unit.
 23. The apparatus of claim 22 whereinthe at least one formation evaluation sensor further comprises awide-band gap photodiode positioned in a bit box.